1. Technical Field
The present disclosure generally relates to well bore tools and in particular to apparatus and methods for conducting downhole operations.
2. Background Information
Oilfield wellbores are formed by rotating a drill bit carried at an end of a drill string. A typical drill string includes a tubing, which may be drill pipe made of jointed sections or a continuous coiled tubing, and a drilling assembly that has a drill bit at its bottom end. The drill bit is rotated by a mud motor carried by a drilling assembly carried on the drill string and/or by rotating the drill pipe. Drilling fluid, also referred to as the “mud,” is pumped under pressure through the tubing from a source called a mud pit located at the surface. The drilling fluid exits the tubing through a drill bit and returns to the surface by flowing upward in an annulus between the tubing and the borehole wall. The drilling fluid is usually a combination of solids, water and various additives selected to adjust the density and chemical characteristics of the drilling fluid.
The drilling fluid serves to lubricate and cool downhole drilling components such as the drill bit. The drilling fluid also serves, when in the annulus as a return fluid, to clean the borehole by carrying cuttings to the surface and to provide hydrostatic pressure against the borehole wall. The composition and density of the drilling fluid in conjunction with the depth of the borehole determine the hydrostatic pressure. The pressure exerted against the borehole wall is usually kept higher than the formation pressure to form a pressure overbalance. The overbalance helps prevent borehole collapse and helps to keep formation fluids from entering the annulus.
Any change in the drilling fluid composition that substantially reduces the density of the fluid may cause the hydrostatic pressure to fall below the formation pressure and allow fluids to enter the well bore. Some fluids entering the borehole may cause corrosion to downhole tools. Left uncontrolled, the entering fluids may cause a “kick”, which is an upward thrust of fluids from the annulus. Such “kicks” can cause equipment damage, damage to the well, environmental concerns, and pose serious safety hazards for personnel at the well site. In some cases, the kick is a result of drilling into a zone of unexpectedly high formation pressure. Kick may also be the result of washout due to unstable formations. In other cases, gases produced from formations quickly reduce return fluid density.
Of course, even while drilling at hydrostatic pressures that exceed the formation fluid pressure, any pore fluids that had once been part of the wellbore rock will become mixed in the drilling fluid. Although this small amount of pore fluid is unlikely to cause any significant change in drilling fluid density, knowing its composition is still very useful information. For example, return fluid containing considerable methane is an indication that a gas zone has been penetrated by the drilling. If the return fluid contains carbon dioxide, certain corrosion inhibiters may be needed in the drilling fluid. Hydrogen sulfide in the return fluid may indicate a need to add scavenging agents to protect both equipment and personnel. For the long term, we also gain more information about the reservoir that helps when planning the minimum required corrosion resistance of materials to be used in the production facilities and when estimating the economic value of the produced hydrocarbons. Hydrocarbons that contain very high levels of carbon dioxide or more than trace amounts of hydrogen sulfide are discounted by what it costs to remove them.